Wireline formation testing has evolved from discrete pressure measurements, introduced in the 1950s to measuring pressure gradients and fluid contacts since the 1970s. Technology introduced in the late 1980s and onwards added interval pressure transient testing, focused sampling, and downhole fluid analysis. Thirty years later, this paper shows data examples of a recently developed formation testing platform in a wide range of environments, and applications, that change how we plan, acquire, and use formation testing. The dual-flow-line architecture of the formation testing platform is designed to systematically address shortcomings of legacy technology, enabling focused sampling in the tightest conventional formations, as well as transient testing in high mobility environments. Specialized pre-job planning software evaluates conveyance options to minimize friction and borehole contact, estimates the available flow rate, compares cleanup performance of the different inlets, and simulates transient testing responses. During the operation, the platform uses hardware embedded automation algorithms that execute routine tasks in a consistent and highly efficient manner, leaving more time for the user to focus on data quality and value of the measurements. Case studies from Mexico, Norway, and the US demonstrate specific improvements in capability and performance. Field data from Mexico shows focused sampling of gas condensate from a heterogeneous submillidarcy carbonate formation in an HP/HT well drilled with oil-based mud. Controlled downhole decompression of crude oil in the flowline at a sampling station in Norway enabled real-time measurement of its bubblepoint pressure to within 6 psi of that measured in the laboratory. Another case study integrates accurate relative asphaltene gradients into an existing reservoir fluid study to prove reservoir connectivity across a large lateral distance in a producing field. Application of the dual packer subsystem demonstrates inflation within four minutes and pure oil samples within 90 minutes on station in a 1.5-md/cp fractured basement formation. The fine pump control at a low rate enabled sampling just below reservoir pressure in Alaska and a case from the Gulf of Mexico demonstrates the real-time impact of fluid properties on the understanding of reservoir architecture and completion design. The presented examples highlight the impact of downhole automation, define the new operating envelope for formation testing in the most challenging environments, and highlight how the technology development leads to decision making on a broad reservoir scale by providing contextual answers rather than an accumulation of facts and figures.

PNPR cluster consists of three fields, namely PX, NX and PR (combined STOIIP ~200 MMstb), located ~300 km offshore of Peninsular Malaysia. Throughout its journey of monetizing marginal waxy crude, many challenges and hurdles have arisen, including sustaining oil production rate above economic threshold, pipeline clogging, and FPSO fuel uncertainties, which requires collaboration between surface and subsurface team to develop unique solutions in managing these downturns. Critically, PNPR cluster is expected to reach economic limit within few years’ time. This paper will elaborate on how IOR is achieved in PNPR cluster, historically and in near future. Ever since first production by PX and NX in 2004, infill drilling campaigns have been needed to sustain production above the economic limit of 5,000 bopd. Later in 2009, approximately a year after PR kicked off its first oil; the14 km pipeline to FPSO was plugged due to wax accumulation as a result of prolonged shutdown. A pipeline restoration project was embarked on involving installation of pipe in pipe (PiP), which utilizes hot water circulation as pipeline heating element. Another complexity has been consistently supplying gas to the FPSO for fuel, which involves a cement packer and adding perforation jobs in gas wells. Additionally, the waxy crude in these fields requires gas lift to be produced, particularly after water production started to escalate. This gives an opportunity to introduce through tubing electrical submersible pump (TTESP) to the field, while reducing dependence on gas lift. Financial wise, cost optimization initiatives are necessary to maintain the operability of the fields. To date, five infill projects have been successfully completed, contributing to IOR by bouncing back PNPR oil production rate. Additionally, a gas cap blow down (GCBD) from NX J80 reservoir also managed to improve reservoir recovery factor (RF) while supplying additional gas for fuel. Meanwhile, the PiP system, an enabler for IOR, has successfully ensures smooth crude oil delivery above pour point temperature from PR Platform to FPSO. In terms of gas fuel supply forecast, proper gas wells production phasing is planned to secure steady supply until 2023. IOR through artificial lift, TTESP is planned to be executed soon in one idle production well with potential gain of 500 bopd, hence eliminating option to workover the well, which is costly. Viewing IOR from economic standpoint, operating expenditure (OPEX) reduction through new philosophies were implemented, including reduction of FPSO charting rate, proactive maintenance and low-cost chemical bull heading, resulting in better cash flow for PNPR. It is expected that existing PNPR wells can recover 2 MMstb of oil through extension of economic life via incoming infill drilling in 2021, translating into 1-2% increase from current RF. Moreover, PX and NX already produced ~80% more reserves than originally booked in the first FDP.

The plug-and-perf (PnP) method is widely used globally for multistage fracturing operations. With only a few jobs performed worldwide, coiled tubing (CT) assisted PnP operations in high-pressure/high-temperature (HP/HT) wells are largely uncharted and most challenging. The "A" field in India has HP/HT formations, with bottomhole temperature (BHT) of 310°F and reservoir pressure of 9,000 psi. Whereas the PnP method is widely used globally, there are few examples in wells with completion restrictions or whose downhole conditions dramatically increase depth inaccuracies and equipment damage. This study describes how to address challenges such as depth correlation (which affects plug-setting depth accuracy), low injectivity, completion restrictions, and heavy brines (which damage CT). To gain further understanding of operations, simulations are sensitized to identify solutions for pumping rates, HP/HT conditions, well kill fluid, milling, and cleanouts where obstructions hindered BHA penetration. The proposed best practices presented here are for primary CT operations involved in the complete PnP cycle, such as wellbore displacement, well dummy run-drift, setting the isolation plug and milling, acidizing using jetting tools, sand cleanout using gels having best performance in HP/HT environment and motor-mill runs with durable resistance in harsh environment, well kill (using 13.65-ppg calcium bromide), and nitrogen lift. The featured case studies describe operations including seven bridge plugs being set at accurate depths and milled after fracturing; cleanout of a 340-m sand column is also featured, as well as well kills with heavy brines. Optimized operational parameters such as CT speed, pumping rates, and the use of smaller outer diameter bottomhole assemblies doubled operational efficiency during those operations.

This paper presents the lessons learnt during an intervention to remove a gas hydrate blockage and reinstate oil production from an oil well in Field D. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water oil field with 10 subsea production and water injection wells tied back to a floating, production, storage, and offloading (FPSO) vessel. Field D was shut down for turnaround maintenance work during the summer of 2016. After the field was brought back online, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity. A number of attempts were made to induce the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, and this restored oil production from the D2 well. To minimise hydrate blockage and oil production losses, the asset team completed a feasibility study to evaluate the viability of installing a second methanol umbilical and a test separator. The hydrate clean-out intervention reinstated oil production from the D2 well, and the feasibility study suggested that installing a second methanol umbilical and a test separator are economically attractive as standalone or joint projects. It is recommended that flow assurance strategies are regularly updated as production fluids change over the lives of petroleum fields, from dry oil production to high water cut production. This paper presents hydrate remediation steps in a producing oil field, and outlines practical methods to justify methanol umbilical capacity enhancement projects.

The objective of this paper is to show the value of using real time remote monitoring system (Automation) in offshore wells and to show a case study from Company for how we successfully used the system to detect well anomalies in real time and perform the suitable corrective action to optimize the well production and maximize well recovery with minimum man-hours. Our company is a leading Egyptian petroleum company with + 200 oil producers on 70 offshore platform; 27 % of platforms include automation system, in platforms without automation system we detect wells problems by performing periodic site visits and check the operating parameters per well., normally it take weeks between two successive platform visits. For platforms with automation system, we install pressure sensors on WH, Manifold, and casing head and temperature sensor on WH., The data being transferred from sensors to office instantaneously, which we successfully made use of, to respond quickly to the problems and achieved maximum well recovery. The offshore oil producer well J-100 was drilled and put on production on Nov. 2015, the well was producing naturally from the attic of the reservoir, it was a mandatory to control the production rate to keep the well producing beyond the calculated critical production rate to avoid water coning. After a while of putting the well on production, well sensors showed several successive abnormal changes in readings which had been captured in real time with the help of automation system, and with data analyzing we found the causes of each phenomena every time (like loading up, a problem in the production choke, etc.) and we succeeded to prepare the action plan, and perform the scope of work as soon as possible. Without the automation system, it would take weeks to detect the problem based on the site visits plan. However, installing the automation system will enhance the response efficiency by saving the time required for problem detection, and improving the quality, density and accuracy of well data. In addition, it will decrease the losses in production rate, and maximize the recovery by optimizing the production rate based on the field depletion plan. In summary, this paper discussing a case study for the value of using real time remote monitoring systems in offshore fields and we used this case to highlight the need to expand the system to include more wells in our field to maximize the field recovery and add considerable benefit to the business.

It is a sobering statistic that 68 of 76 proposed major offshore developments were cancelled in 2015. There has been gradual improvement since then with system cost reductions and the oil price recovery, but nonetheless prospects that could be very profitable with the right development concept have been rendered uneconomic by overblown cost estimates. Conversely prospects with poor economics may go ahead due to overestimated production expectations. Production forecasts are generated by reservoir models. These models are often first constructed early in the development process, and refined multiple times as the process progresses and more information becomes available, e.g., from appraisal wells and production history. Meantime, production system design and sizing are often performed by different groups in the E&P company or by subcontractors in virtual isolation from each other. Updates from the reservoir modelling are not necessarily shared between these groups resulting in disconnects that can impact project viability and economics. Better collaboration between these groups and use of integrated reservoir and production system models address and sometimes resolve these issues. However, even in cases where integrated models are used, rather than harnessing the full power of the reservoir model, it is often dumbed down. This is done primarily in an attempt to save time, but it results in poorer representation of the actual reservoir response, e.g. losing the effect of well interference and failing to capture the pressure distribution and pressure changes with time in the reservoir. In this paper some real examples are provided of disconnects and lack of modelling fidelity with the potential for severe consequences on project economic performance. The four examples that will be discussed in this paper are as follows: Over-simplification of the reservoir representation for a gas field led to a proposed high- capacity subsea compression system being uneconomical. Reevaluating with a full reservoir model showed the compression system was over-sized and would underperform. Correcting these issues transformed the project economics and enabled the project to progress towards the FID. A simplified representation of the reservoir for a tieback resulted in insufficient natural production (no artificial lift) to be economic and insufficient production increase to justify subsea pumping. However, when reevaluated with more detail, the project became economical using a pumping concept. Passing a simplified production forecast from the reservoir team to the flow assurance team for a long tieback development resulted in overlooking the most onerous period of production for thermal management. If this oversight had made its way into the final design of flowline insulation, the tieback may well have plugged with wax deposits within a few years of operation. Use of complete forecasts within an integrated simulation framework prevents this kind of issue. Use of an inappropriate simplifying assumption while evaluating a brownfield redevelopment resulted in an overestimated production potential of the proposed new wells. When the error was corrected, an additional iteration of the development concept to downsize it was required which delayed first oil. Integrated reservoir and production system modelling avoid these kinds of planning and investment mistakes happening in the first place. This paper challenges the notion that detailed, integrated simulation is not required until later stages (FEED, execution) of a field development project, if at all. The presented examples are based on actual project experience. They provide quantitative evidence that integrated simulations have avoided costly development concept iterations and even more costly mistakes. Sometimes this allowed assets with marginal economics to be reconsidered for the operators’ project execution pipeline. Sometimes it resulted in the need to revisit economic analysis and development concepts due to initial overestimation of well performance.

This paper presents the drivers used to determine the preferred method for pre-commissioning the flexible flowlines for a shallow water gas development project in Trinidad by BP. Upon mechanical completion, the flexible flowlines are required to be hydrotested to ensure the system is leak-free. After the hydrostatic pressure test, the industry norm is to dewater and dry the flowlines. However, the system architecture (one flexible flowline per well) requires subsea maneuvers around the subsea trees, which brings about significant risk of damaging the trees. Several alternatives (shown below) were proposed: Base Case – The original plan was to remove the tree choke insert, then insert the newly developed temporary subsea pig receiver into the choke body. Nitrogen (N2) and gel pigs are used to push water from the topsides to the subsea tree. The specification is to reduce the flowline water content to 5% or less. Alternative 1 – Involved not using the gel pigs and only using N2 gas to push the water out from the topside to the subsea tree. This alternative would not require a temporary pig receiver, which reduces the chance of damaging the choke insert profile. Alternative 2 – Involves dewatering the flowline using the umbilical tubes (methanol lines). This has an advantage in that there is no need to pull the subsea tree choke insert, which reduces the risk of damaging the trees. Alternative 3 – Do nothing and leave the seawater in the flowlines. The production stream would be used to push the water into the production system during first gas production (well offloading). The study concluded that all three alternatives were technically feasible. For Alternative 3, an additional assessment was conducted to determine the impact of seawater on the flexible pipe when exposed for an extended time. Ultimately, the decision was made to not dewater the flowlines. The corresponding well offloading (flow back) procedure and a contingency plan were then developed. The Juniper development had first gas in September 2017. The first well offloading with integrated de-watering went as planned. The decision of not-dewatering the flowlines was proven to be a good decision by reducing risks, costs and simplifying the schedule during the commissioning period.

The paper uses a case study approach to present the challenges to develop a large and thick oil carbonate reservoir, full of opportunities but also of uncertainties. Additionally, Libra block development is under a Production Share Contract that was award to a Consortium where Petrobras is the operator in partnership with Shell, Total, CNOOC and CNPC. The paper will briefly present the de-risking plan and detail the EWT Program implementation and the way it is helping the full field development, which consists of four mega ultra deepwaters projects.

This paper uses a case study approach to present the challenges to develop a large and thick oil carbonate reservoir that is full of opportunities and uncertainties. The Libra block, located in Santos Basin ultra-deep water, in Brazil, has been developed under a Production Sharing Contract that was awarded to a Consortium where PETROBRAS is the operator in partnership with SHELL, TOTAL, CNOOC Limited and CNPC. This document will briefly present the de-risking plan, and detail the EWT Program implementation and its impact on the Mero area development, which consists of up to 4 (four) mega projects and altogether represents over 20 billion dollars in CAPEX investment. In addition, the results will show how the achievements achieved by the EWT project provided an extensive technological legacy to the offshore oil & gas industry.

Since their initial discovery in the 1960’s, gas hydrates have been considered to be an important potential source of unconventional natural gas. Significant progress has been made relative to our understanding of the geologic and engineering controls on the ultimate energy potential of gas hydrate; however, more work is required to realize the promise of gas hydrates as a future energy source. Gas hydrates have been encountered, recovered or inferred to exist in numerous sedimentary basins in Arctic permafrost settings, regions of alpine permafrost, marine sediments of outer continental margins and in deep lakes. Despite the great abundance of potential gas hydrate resources in the world, a large portion of these resources reside in clay-rich sediments and fracture dominated reservoir systems, and are not generally considered producible with existing technology, but may have future potential with the emergence of new technologies. For a large portion of the world, gas hydrate in sand reservoirs have become a viable production target and the focus of the first production testing efforts. Production tests in Arctic Canada (Mackenzie Delta) and Alaska have shown that gas can be produced from highly-concentrated gas hydrate accumulations in coarse-grained (i.e., sand rich) reservoir systems with conventional production technologies. Production can be achieved through the depressurization method and by more complex methods such as molecular substitution (e.g., CO 2 -CH 4 exchange). In 2013, the gas hydrate production test was conducted in a marine setting in the offshore of Japan. An additional test was conducted in Japan in 2017 to further evaluate alternative well completion technologies. Also in 2018, China initiated a 60-day gas hydrate production test in the Shenhu region of the South China Sea. This report reviews the results of gas hydrate engineering and production testing studies associated with the Mallik, Mount Elbert, and Iġnik Sikumi projects in northern Canada and Alaska. The results of the marine gas hydrate producing testing efforts in the Nankai Trough (Japan) and in the South China Sea (China) are also summarized.

The FPSO Kaombo Norte came on stream on July 27 th offshore Angola. When both its FPSOs will be at plateau, Kaombo, the biggest deep offshore project in Angola will account for 15% of the country's oil production. It produces light oil from six fields scattered over an 800-square-kilometer area. Gindungo, Gengibre, and Caril fields are connected to the Norte FPSO while Mostarda, Canela, and Louro fields will be producing on FPSO Sul. The full development stands out for its subsea network size with more than 300 kilometers of lines on the seabed within 1500-2000m water depth, including subsea production wells more than 25km away from the production facility. In order to secure a safe First-Oil and to smoothly start-up the production, a detailed and cross-functional study was carried out. The first step was to start from a clean slate by forgetting all previous startup scenarios: the three loops candidate to start-up hydrocarbon production were re-analyzed in depth to evaluate strengths and weaknesses. A task force composed of all involved disciplines, including contractors, was put in place in order to apply a cross-functional approach. Constraints from reservoir up to topsides were analyzed providing an overall picture and clear ranking to develop the start-up strategy. An ambitious planning of the commissioning activities combined with a relatively short-term reservoir management were crucial to lock production loop priorities with water injection and gas export systems readiness. The work jointly performed contributed to serene environment for a safe start-up and ramp-up. Following the assessment, decision was made to start first the most "powerful" reservoir despite a challenging flowline. The relatively high initial pressure and oil undersaturation, the robust open-hole gravel-pack completions and high productivity wells were beneficial to stabilize the multiphase flow in the subsea network. Improvement of the production was rapidly made with the start-up of the second production loop only fifteen days after. Postponement of the water injection system and the availability of the riser base gas lift were judiciously calculated: the readiness of these systems arrived in due time to respectively slow down the natural depletion of the reservoirs and improve the wells eruptivity and stability of the flowlines. Our capacity to re-invent ourselves and leave behind individual priorities conducted to a collective success captured in the outstanding production levels since early days of field life.

This paper addresses the innovative appraisal strategy applied to the Libra project; located in ultra-deep waters offshore Brazil. It details the key role of the Extended Well Test (EWT) Program, within the field overall Risk Mitigation Plan, as well as its interfaces with additional appraisal activities. The Value of Information (VoI) for the main acquired data is described, highlighting the associated impacts for the full field development and validation of the enhanced recovery strategy. A case study approach details how the whole EWT project maximized the acquired information, mainly from a reservoir point of view. Although the EWT approach is not new to Petrobras in the offshore environment, this is the first one with simultaneous oil production and gas reinjection. Several reasons justify the use of the industry’s first dedicated offshore EWT system with this capability. Gathering data on the main dynamic parameters of the field was critical to speed-up the development, with an acceptable risk level. The incorporation of these data in the reservoir models and the impacts in the most relevant development decisions are also described. The chosen methodology brought many opportunities, as well as challenges to interpret the data and to incorporate them in the reservoir models. Furthermore, the capability to produce without continuous gas flaring makes it possible to apply such approach anywhere else in the world.

The paper uses a case study approach to present the challenges to develop a large and thick oil carbonate reservoir, full of opportunities but also of uncertainties. Additionally, Libra block development is under a Production Sharing Contract that was awarded to a Consortium where Petrobras is the operator in partnership with Shell, Total, CNOOC Limited and CNPC. This paper will present the main subsea technological achievements made during the execution of the Libra Extended Well Test (EWT) Project so far and also future technologies that will contribute to overcome the full field development challenges.

This study explains the large injectivity changes observed in the field, how to remedy it, and how to ensure fracture containment in channel sand reservoirs. The case study field is located offshore Ghana and is a channel sand reservoir. Water injection was initiated for pressure maintenance and waterflooding under fracturing conditions. The injection wells are designed to ensure high and sustainable injection rates while maintaining the integrity of the cap rock. The injection bottom-hole pressure (BHP) was history-matched to investigate the impact of stress profiles, reservoir shapes, injection water quality, poroelastic and thermally induced stress changes. The injectivity decline was found to be a result of changes in stresses caused by the channel boundaries and, to a lesser extent, near-wellbore formation damage. The rapid increase in pore pressure and the resulting decrease in injectivity is unique to these kinds of channel sands. Once the origin of the decreasing injectivity was identified, remedial actions were recommended and predictions for future injectivity were made ensuring containment of fractures.

Deepwater natural gas hydrate resources potentially exceed all other conventional and non-conventional hydrocarbon resources on a world-wide basis. However, before these offshore gas hydrate resources can be classified as reserves, it must be demonstrated that gas hydrates can be produced under conditions that make economic sense. The purpose of this paper is to provide an overview of the technical issues that will challenge the development of deepwater natural gas hydrates.

The Advanced Technology Lab has developed a Fire Test Facility that became operational in spring 2015. This paper describes a fresh approach to the systems engineering process path taken during development to capture new capabilities and opportunities for such a system. New functions and safety features are discussed, as compared to the original system that was replaced. Recent fire incidents on offshore rigs have increased interest in meeting rigorous standards for fire safety. As a result of a needs assessment, a replacement Fire Test Facility (FTF) was developed in order to test offshore equipment. Offshore valves and connectors on rigs must be certified to withstand sustained fire conditions per American Petroleum Institute (API) standards 6FA/B/C. The requirements include surviving fire temperatures up to 1800 F for a period of 30 minutes, while holding internal pressure and even withstanding bending loads. Updated safety regulations at the company led to a review of the original Fire Test Facility, and it was determined that a new system was necessary to incorporate blast protection, controls automation, and situational awareness. After establishing needs and goals from our internal customer, derived requirements were generated. Using the company’s system engineering "engine", this led to a design that met customer requirements and enhanced safety. Improvements over the original system include a 6-sided bunker structure, passive ventilation, gas safety purges, remote operation to keep workers outside the hot zone, and real-time charting to assess test performance. After integration of the facility, a verification matrix was used to assess system functionality and performance. The improved system allows for quicker test turnaround, and more refined burn tests at reduced costs compared to using external test facilities. Mock fire tests can be performed to assess "what-if" conditions prior to actual testing of equipment. Several tests were successfully performed to API standards. Results and observations throughout the systems engineering process, including systems integration and checkout of the Fire Test Facility are provided.

This paper describes the wells completion design, operational performance and use of intelligent completion by Libra Consortium for EWT wells. Additionally, it will describe new technologies that will support the full field development. The paper presents the de-risking plan EWT Program implementation to help full field development, which consists up to four ultra-deepwater mega projects. The EWT wells were assumed as keepers, thus designed as convertible, with metallurgy requirements for both oil production and Water Alternating Gas injection. The intelligent completion, with multi-position valves for each production zone, was selected to allow choking-back gas coning, early gas breakthrough or water production in one zone, while another remains opened. These valves were useful to determine vertical communication between different reservoir zones, making it possible to have buildup in one zone while producing another. Four appraisal wells were completed, for the EWT program up to now, using a full-dual rig. Three of the completions were in sequence, providing a sound learning curve with a significant time reduction, and no installation problems. It was noticeable a correlation between improvement in operational efficiency and a decrease in HSE incidents. The use of intelligent completion made possible an efficient well stimulation, avoiding inter-zonal communication during the acid job. A production rate higher than 60 kboe/day was reached and 100 MM scf/day gas was re-injected. This injection rate implied risk of control lines fatigue due to induced vibration, therefore a Computational Fluid Dynamics (CFD) study was required to determine the maximum injection rate. The Operator implemented mitigation measures for intelligent completion valves actuation since some operational difficulties were observed during the EWT. These situations did not affect the EWT information acquisition plan, but represented significant operational experience for Mero Field future development projects, where multiplexed intelligent completions and open-hole intelligent completion are being also considered. The approach taken by Libra Consortium helps to gain early experience about well design for carbonate reservoirs and intelligent completion behavior, with high CO 2 and GOR, where gas re-injection is a necessity and the use of intelligent completion is a mandatory strategy. The performance of the completion design fitted the field evaluation purpose and the wells will be successfully used as keepers.

The objective of this study is to analyze in detail a process for designing by means of numerical simulation a field test of gas production from hydrate deposits, and to discuss modeling results associated with several such planned tests. The paper discusses comprehensively the data required for a reliable estimate of gas production, and provides insights into production conditions and test well operating parameters that can adversely affect a planned test. The design process begins with the development of a reliable geologic model. It is followed by an analysis of the system stratigraphy, the identification of the hydrate-bearing zones and the associated interlayers, the definition of the initial conditions (pressure, temperature, phase distributions, and geomechanical stresses), the identification of all key media properties (flow, thermal, geomechanical), and the definition of success criteria for hydrate production tests. The geologic model is of paramount importance because it can define the system boundaries. We explore the relative importance of lateral vs. top and bottom flow boundaries within the context of the limited time frame of a field test. Initial pressures P in hydrate accumulations are relatively predictable as they are almost invariably hydrostatic. The initial temperature T distribution is important because T is the dominant parameter controlling the hydrate behavior. Knowledge of the P and T distributions are important in determining true time-invariant P- and T-boundaries. Other important initial conditions are (a) the spatial distribution of the possible phases and (b) the geomechanical stresses in the system and its surroundings. We discuss possible sources of the necessary data through analogs even when direct measurements are unavailable. We investigate the effect of heterogeneity in various parameters, and in the choice of the coordinate system. We explore the impact of spatial discretization, an important subject that has yet to be fully investigated. Finally, we provide modeling results covering a wide range of designs for production tests in oceanic and permafrost-associated hydrate deposits that describe fluid production and the flow and geomechanical system response, as well as implications for the well design and construction. To the authors' knowledge, this is the first paper discussing in detail the recommended process for the design of field tests of gas production from hydrates, and of the key issues that can affect not only production but also the flow and geomechanical behavior of the system during the test and the definition of the well construction requirements.

Subsea Pumping Well Intervention Systems (SPWISs) include a reeled fluid conduit (or riser) that connects a surface pumping spread to a subsea tree via a subsea safety module. Current pipe technologies used for fluid conduits are limited in terms of their pressure capability, volume of fluid they can supply, fatigue performance or the ease with which they can be deployed. Thermoplastic Composite Pipe (TCP) addresses many of the limitations of existing products, and therefore is attractive as an alternative. This paper describes the qualification of a TCP as a SPWIS fluid conduit. The TCP is manufactured from carbon and S2-glass fibre, laminated with a Poly Ether Etherketone (PEEK) matrix. The TCP was qualified following the processes recommended by DNV-RP-A203 "Qualification of New Technology" and the specific guidance given in DNVGL-RP-F119 "Recommended Practice for TCPs". The former defines a structured process for developing a qualification basis, assessing the risk of all potential product failure modes, and then mitigating those risks through the collection of qualification evidence. The latter provides a methodology based upon a testing pyramid and a linked structural model, to gather the appropriate qualification evidence for a TCP. The results of the TCP qualification are presented in three areas, materials testing, pipe testing and structural analysis. The material testing focussed on characterising both pure PEEK, and the properties of individual carbon and S2-glass plies in the composite laminate. Testing was performed across the design temperature range (4°C to 80°C), and was used as input into the structural model of the TCP that was developed. At a pipe scale a comprehensive set of single and combined static load cases were tested, including axial tension and compression, internal pressure, bending, and bending and internal pressure. These test results were compared against the predicted TCP performance given by the structural model, both in terms of stiffness and ultimate failure. In addition to the static testing, long term performance of the composite laminate was also characterised. Laminate testing methods were developed for fatigue and stress rupture, and the test results used to construct life curves for both failure modes. The combination of both the materials and pipe testing, and the structural analysis, culminated in a qualification certificate being issued for the TCP by an Independent Verification Agent. DNVGL-RP-F119 is a new recommended practice that was published in December 2015. This paper presents one of the first applications of the recommended practice to a TCP product, and therefore provides valuable insight into the practical implementation of DNVGL-RP-F119. In addition, qualification of a TCP as a SPWIS fluid conduit offers the potential to enable more frequent and effective well interventions, thereby improving the productivity and ultimately reducing the cost of subsea wells.

Development of assets in new frontiers can be quite costly, especially in deep-water and ultra-deep waters. These developments have many uncertainties, and each has an associated risk to both operations and project economics. Leveraging the fact that a significant amount of information has been (and continues to be) gathered in public and/or private domains for many of these assets/wells, a multi-year effort to build a data-mining framework for establishing whether well completion and production performance could have been accurately predicted during various stages of deep-water development ("Pre-Discovery," to "Exploration," through to "Mature Fields") was undertaken. The final results of this work were incorporated into a selection/prediction software tool and database for decision support. The work helps establish priority for data acquisition and data values throughout asset development. The project created one of the largest privately held databases of GoM well information: five different publicly available and privately owned GoM datasets were integrated to obtain field-scale geologic and reservoir properties, well trajectories, schematics, drilling, completion and production data for thousands of fields and wells in the GoM. Multiple derived attributes were then calculated using Petroleum Engineering relationships to enhance the reservoir characterization and well performance comparisons. Historical well production data, together with periodic well test results, were used to calculate well productivity indices, skin factors and contacted volumes; changes in these values were analyzed over the course of each well's lifecycle to determine its relation to completion designs, production practices and performances, and/or workovers. Rigorous data mining techniques, including a variant of Principal Component Analysis (PCA) and K-Means Clustering, were used to determine the most prominent attributes governing the intrinsic performance properties of reservoirs ("uncontrollable parameters"). Once subjected to clustering techniques, the uncontrollable parameters indicate several main performance clusters, each of which could be uniquely identified by its paleontology, rock type, reservoir properties and sedimentation/folding regime. Further, each main cluster was observed to be sub-clustered into groups – the wells in each such group having similar completion and production practices (AKA "controllable practices"). Petroleum engineering know-how was used to define well performance attributes and categories to analyze ("objective functions"), which in turn showed a strong relationship between uncontrollable parameters and controllable practices for the performance of each group of wells. Well performance can indeed be predicted with a certainty that depends on the data available: often to within 65%, 80%, and 95%, respectively, depending on the data availability at that stage of a given well's development, from "Pre-Discovery," to "Exploration," through to "Mature Fields".